Amplify Energy Corp. (AMPY) Q4 2016 Earnings Report, Transcript and Summary

Good morning. My name is Jennifer and I will be a conference operator today. At this time, I’d like to welcome everyone to the Fourth Quarter and Yearend 2016 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. [Operator Instructions] Thank you. I will now turn the call over to Mr. Jason McGlynn, Investor Relations Director. Please go ahead, sir.

Thank you, Jennifer. Good morning, everyone, and welcome to Midstates Petroleum’s fourth quarter and yearend 2016 earnings conference call. Joining me today as speakers on our call are Jake Brace, our President and Chief Executive Officer; and Nelson Haight, our Executive Vice President and CFO. Jake will begin with an overview of operational and financial highlights. Mark will follow with additional details on operations, then Nelson will review the financial details for the third quarter and provide guidance for the fourth quarter. After Nelson, Jake will make some follow-up comments, and then we’ll take your questions. Before we begin, please let us get the administrative details out of the way with our Safe Harbor statement. This conference call contains forward-looking information and assumptions, which are subject to risks and uncertainties, and actual results may differ materially from those projected in these forward-looking statements. Please refer to Midstates Form 10-K that will be filed shortly with the SEC for a discussion of these remarks. Also please note that any non-GAAP financial measures discussed in this call are defined and reconciled to the most directly comparable GAAP measure in the tables in yesterday’s earnings release. Now I’ll turn the call over to Jake for his comments.

Thanks, Jason and good morning, everyone and thank you for joining us today and thank you for your interest in Midstates. As most of you are aware, we successfully completed our restructuring process on October 21st of last year and emerged from bankruptcy a stronger, healthier company that is positioned to grow in the current commodity price environment. 2016 was not only an important year on the financial front. It was a pivotal year from an operations standpoint. Our operations and land teams were able to exploit the weakness in the marketplace to drive efficiencies in our operations to reduce costs and increase profitability and to greatly increase our land position and future drilling locations through farm-in arrangements that deliver attractive economics to Midstates and give us access to land that was previously unavailable to us. On the operations side, we were able to reduce our average well cost in 2016 to under $2.6 million, down from a 2014 average of $4 million. Importantly, only 35% of these savings were achieved through service cost reductions with the remaining 65% achieved through efficiency gains. We have begun to see some service cost inflation in 2017 and expect this to gradually continue throughout the year, but we expect our efficiency gains to stay in place. In addition, we have taken steps to fix some of our service costs for the foreseeable future. Despite this, we are currently expecting our average well cost to increase to about $2.8 million this year. Moving on to land, during the last year, our land team was able to opportunistically bolt on over 35,000 net acres to our premier Miss Lime position in Woods and Alfalfa Counties. This is an increase of over 50% from year end 2015. This greatly expanded our footprint in the heart of the play and provided us access to acreage in locations that we otherwise might not have been able to acquire. Now I'll move on to recap our year end reserves. We ended 2016 with approved SCC reserve case of 177 million BOE with a PV-10 at SSC pricing of $578 million. Our proved reserves increased substantially year over year, primarily due to the company's recently completed restructuring and its improved liquidity at year end 2016. By contrast, at the end of 2015, the company was unable to record any PUDS due to SEC rules which prohibit the booking of PUD reserves if an entity lacks the access to capital resources necessary to develop those reserves. At year end 2016, we clearly had access to the necessary capital and thus were able to include the PUDS in our reserve case. Finally on reserves, utilizing a February 6, 2017 strip pricing and more accurate representation of the current value, this proved reserve cases is 188 BOE with a PV-10 of approximately $1.1 billion. Now I'd like to provide a little color on our salt water disposal situation. As most of you are aware, in early 2016 the Oklahoma Corporation Commission or OCC, requested that operators restrict their injection volumes into the Arbuckle formation. As related to Midstates, the OCC requested the company cap its Arbuckle injection at approximately 135,000 barrels of water per day, with individual injection well volumes limited to no more than 20,000 barrels of water per day on a 30 day rolling average. After multiple meetings with the OCC, we developed an action plan to divert injection volumes away from the Arbuckle and into other injection zones that are prevalent within our footprint. We strategically drilled new non-Arbuckle disposal wells and converted existing non-producing vertical wells into non-Arbuckle injection wells. All these new disposal wells are linked to our looped SWD pipeline system which gives us great flexibility in our operations and to comply with the OCC’s request. We reached compliance with the initial OCC directive in August of 2016 without any meaningful impact to our production or our operations. And we continued to add additional non-Arbuckle injection capacity throughout the remainder of the year in order to stay ahead of any additional restrictions that could be requested. That decision proved [prudent] as in the last two weeks, the OCC made an additional request to operators to further limit individual injection well volumes to approximately 15,000 barrels of water per day on a 30 day rolling average. Due to our efforts to add additional non-Arbuckle capacity during 2016, we are able to leverage the flexibility of our looped SWD system to comply with this request, again without any meaningful impact to production or operations. In 2017, we will continue our strategy of adding non-Arbuckle disposal capacity to maintain optionality and have the flexibility to grow production moving forward. In that regard, we currently have six non-Arbuckle injection wells with all the permits approved, just waiting to be drilled as needed. With that, I'll turn the call over to Nelson Haight, our CFO.

Thanks Jake. Let me start with a few details on our capital structure and follow up with a few highlights from the fourth quarter and provide 2017 guidance and wrap up with a quick update on hedging. After successfully emerging from our restructuring in October 2016, we have a fairly clean and straightforward capital structure, with approximately 25 million common shares outstanding and a $170 million first lien revolving credit facility maturing in 2020 and that provides sufficient liquidity and an excellent platform for future growth. At year end 2016, we had approximately $77 million of liquidity consisting entirely of cash on the balance sheet and net debt of approximately $51 million. Currently we are at approximately $85 million of liquidity, with net debt of approximately $43 million. With respect to our credit facility, our credit agreement includes a number of atypical provisions negotiated as part of the restructuring, including a holiday on borrowing base redeterminations until April 2018, a $40 million reduction in borrowing availability during that holiday period, as well as limitations on future capital spending. The improvement in commodity markets over the last 12 months, together with aggressive cost management, have improved the expected returns in our drilling program, and as a result we are re-evaluating our credit facility to determine what steps we can take to provide us with more operational flexibility to invest in our assets and grow production and reserve value. With respect to our fourth quarter performance and 2017 guidance, with one drilling rig operating in the Mississippian line, we generated $35 million in adjusted EBITDA during the fourth quarter, outpacing operating capital expenditures of $22 million by approximately $13 million. As we move further into 2017, we anticipate continuing to operate with an internally generated cash flow and currently available cash. For the full year 2017, assuming a one rig drilling program, we currently expect to spend between $90 million and $100 million of operational CapEx, with our focus being solely on our Miss Lime assets and generate between $125 million and $145 million of adjusted EBITDA. Production in the fourth quarter totaled 25,259 BOE per day, down from 28,059 BOE per day in the third quarter. About 83% of fourth quarter volumes or 20,903 barrels of oil equivalent per day came from our Mississippian Lime properties, while 17% or 4,356 BOE per day was from our Anadarko Basin assets. Assuming a one rig program in 2017, we currently anticipate working through the remainder of this base production decline this year and expect our forward production to be relatively in line with our 2016 exit rate. As such, we expect our full year 2017 production to come in at between 20,000 and 23,000 BOE per day and our production mix to remain generally consistent with our 2016 average. Moving on to expenses, fourth quarter cash operating expenses, which include LOE production taxes and cash G&A that excludes transaction restructuring and advisory costs, totaled $28.4 million or $12.22 per barrel of oil equivalent. During 2016, we were able to make meaningful gains on our cost management initiatives by significantly reducing G&A expense and driving efficiency gains in our field operations, which partially offset the EBITDA impact of declining production over the same period. Year over year we reduced total cash operating expenses by approximately 16%. Our lease operating work over expenses totaled $18.6 million or $8.01 per BOE in the fourth quarter. For the full year 2017, we expect our LOE and work over expenses to be in the range of $8 to $9.25 per barrel of oil equivalent. Gathering and transportation expenses associated with our main gas processing arrangement in the Mississippian Lime totaled $41 million or $1.78 per BOE in the fourth quarter. In 2017, we expect these costs to range between a $1.75 and $2.25 per BOE. Fourth quarter severance and other taxes totaled $1.7 million or $0.74 per BOE. For the full year of 2017, we expect severance and other taxes to be between $0.75 and $1.25 per BOE. Fourth quarter general and administrative expense was $8.1 million or $3.50 per BOE, which included non-cash share based compensation expense of $4.2 million or $1.81 per BOE. Going forward, to better reflect actual G&A efficiency, we will utilize an adjusted cash G&A number, which excludes non-cash comp and other non-recurring items and does not include a reduction for G&A items that are typically capitalized. In 2017 we expect adjusted cash G&A to range to $3.25 per BOE. Turning to hedging, during the first quarter of 2017, we restarted our hedging program. For 2017 we have put in place a combination of swaps, two way and three way costless collars to hedge approximately 50% of our forecast oil production. With respect to 2017 natural gas, we have utilized a combination of swaps, two way and three way collars to hedge approximately 58% of our forecast gas production. Additionally, we have begun to layer and hedge protection for 2018. A detailed summary of our current hedge position is included in the release and is posted on our website, along with all the guidance I’m providing today. Going forward, our hedging strategy will be focused on providing downside price protection to protect operating cash flows, while still allowing for meaningful participation in any upside price movement. Our current bias is towards a combination of swaps and costless collars, but we closely monitor the futures market and will add additional hedges and utilize different instruments as the market opportunities present themselves. With that, I'll now turn the call back over to Jake.

Thank you, Nelson. Like everyone else in the energy space, we are happy to see that commodity prices have recovered from the depths of 2016 and have been somewhat stable at current levels. This recovery, coupled with the deleveraging of our balance sheet, has provided us a unique situation where we can generate significant free cash flow with a one rig development program. This gives us flexibility to either increase our rig count in 2017 or to build cash and deploy capital at a later date. Whatever we do, we are committed to preserving our liquidity through an intensely focused capital discipline and continuous improvements in operational excellence. We believe we have the liquidity needed to create value in the current environment and preserve optionality as we move forward. We continue to exploit our premier position in the Miss Lime while we explore avenues to unlock value in the Anadarko Basin. In closing, our accomplishments in 2016 give us a lot to be excited about. We have proven our ability to quickly respond to a downturn, both financially and operationally, to be proactive and responsive to the changing regulatory landscape and now we have significant flexibility to allow us to manage our business in a disciplined way in any pricing environment. We have an outstanding team of employees and contractors who know the rock very well and continue to operate and drill consistent low cost wells day in and day out. Our GAA performance is quite good and we believe we can add a rig with little to no incremental G&A. We have reserves worth approximately double our market cap and the ability to grow them despite SWD restrictions. In some we think we have a very bright future. With that, Jennifer, we're ready to take any questions.

[Operator Instructions] Your first question is from Ron Mills with Johnson Rice.

Good morning, Jake. Just a question on - and Nelson and all, but on the one and two rig scenarios you have out there, how much of the capital budget is expected to be spent on incremental saltwater disposal capacity versus the focus in the Miss Lime and would be second rig if you added it in the second half of the year also be directed to the Miss Lime.

I'll give you the general answer. Nelson can give you some more specifics, but yes, if we added a rig, we'd be focused on the Miss Lime and we likely - second rig, we likely need to spend a little bit extra on saltwater disposal. But the short answer is, the restrictions have not been sort of - have not caused meaningful increases in our CapEx spending as relates to SWD. Nelson, I don't know if you have the specific numbers.

Yes. On that saltwater disposal, I think under either case it being stay close to that range that we've put forth in the guidance deck, which was between $14 million and $18 million. I think that allows for two, possibly three saltwater supposable wells this year.

Okay, great. And then on the Miss Lime, the type curve that you have out there, you know at kind of current oil prices show somewhere plus or minus 40% rate of return. Do you - I know you’ve shown a little bit of an increase in well costs this year. But are there any more efficiencies to be gained or when you have that 35% of your kind of service cost inflation that can impact you, will that flow through to your well cost?

Yes. I think as we indicated, we're - we continue to get efficiencies, but our well cost performance is I think on a gradual upward slope right now. We're seeing increased prices for some of the service suppliers and we're not able to offset those increases through drilling efficiencies. Even though Mitch and his team continue to improve the way we're doing things, we’re not able to offset those in this environment. And we're also quite frankly seeing some scarcity as a lot of the activity has moved over to the Permian. A lot of the suppliers have moved their activity over to the Permian and we're finding it a little bit difficult to get frac spreads and things like that. So we're managing it well. We think we're - we think we - as I said, we think we can contain the costs at the $2.8 million but we do think that things are on a slightly upward slope.

And then last one on the Miss Lime. The type curve, is that taken - is that more of kind of the heart of the play Woods, Alfalfa County line area? Is that an average?” And I'm asking because it sounds like the recent acreage additions over the course of last year, at least it was described as such that you have really increased the exposure to the core place. We’re trying to figure out if your PUD type curve is for the core or average.

Well, the type curve that we’re using is for the average over the entire Miss Lime play.

But the activity will be focused more on kind of the heart of the county line area. Is that fair?

I don't know that that's fair. We're moving - right now we've moved a little bit southeast of what used to be thought of as the core. And but last year we were up to the northwest a little bit. So we're moving all around, but the area is just not that big down there. It's all within 10 miles of each other or something. So it's not like we're venturing far afield.

Great. Thank you for all the comments.

Your next question is from David Beard with Coker Palmer.

Good morning gentlemen. Thanks for taking my call. A couple of big picture questions. Given the saltwater disposal issues throughout the mid-con, do you want to stick in this region and try to use that to your advantage when you’re looking to acquire acreage or do farm-ins or are you looking outside the basin? How are you thinking relative to acquiring more well locations?

No. We're focused on the Miss Lime. We think we know the rock there very well. We like it. We’re able to drill good, very consistent wells there and we understand that the play is a little bit out of favor, even a lot out of favor, but that gives us an opportunity to acquire acreage at very attractive economics to us. So we're focused on the Miss and our drilling activities there, our land. The land that we're acquiring is there and we're not looking in any other basins.

Okay. And do you have any metrics, evaluation metrics you could share with us of per acre that you're seeing or a range or something like that?

I don't want to talk about those per se. It's pretty attractive, especially when we do some of these acquisitions via farm-in, that those economics are pretty attractive. But I don't really want to publish those right now.

No, totally understand. And then just looking at the Mississippi Lime drilling program, you had the farm-in areas on your map on page 19. Could you just help us understand what was attractive about those relative to where you're drilling in 2015? And it looks like there are some more opportunities in and around those “blue areas.” Just help us understand a little bit what you see there.

Well, I'm not the geologist, but our G&G guys found those areas very attractive and right now our rig is down in that area to the southeast and we're drilling our first well in that area, but we're very enthused about the rock there. We think that it's every bit as good as the rock that we've seen in the other areas. And the whole idea was we get our geologists to state where do they like the rock? We see who owns the acreage. We talk to them and we try to cut an attractive deal and that's what we've done.

No, that makes sense. And last question, just about the third rig, it seems like you have the cash flow to add it. What would cause you not to? Is it inventory? Is it well pricing, something else?

Second rig to be clear.

Yes. Second rig. Sorry.

It’s okay. We're not going to get ahead of ourselves here. We have to find the rig. We have to plan it out. The big restriction right now is with - I think as Nelson mentioned, with the RBL and so we have to clear that up. So those are the things that could get in the way with it if we can't come to some satisfactory resolution in the RBL, then it wouldn't allow us to add the rig. We have plenty of inventory. We've got plenty of areas we'd really like to drill. We have the cash flow and liquidity to add the rig, but we need to work through the situation with the RBL lenders.

Okay, good. And then the time frame or milestone relative to that process?

It’s as soon as we get off this call, Nelson is going to be working on it.

Yes. No. I totally understand that. Appreciate all the time. Thanks guys.

That was our final question for the day. I would like to turn the call back to Mr. Jake Brace, President and CEO for closing remarks.

Thank you, Jennifer and thanks to everybody who's on the call. We appreciate your interest in Midstates and we will look forward to talking to you at the end of the next quarter. So thanks everybody.

Ladies and gentlemen, this does conclude today's conference call. You may now disconnect.